1. Field of the Invention
This invention is related to methods for acquiring and processing nuclear magnetic resonance (NMR) measurements for determination of longitudinal and transverse relaxation times T1 and T2 and related petrophysical properties. Specifically, the invention deals with use of an expert system downhole for acquiring and evaluating NMR measurements contemporaneous with the drilling of wells in a formation including a carbonate rock, and with use of a downlink communication from the surface for modifying the parameters of the downhole acquisition and processing system.
2. Description of the Related Art
Nuclear magnetic resonance is used in the oil industry, as well as other industries, including and particularly in certain oil well logging tools. NMR instruments may be used for determining, among other things, the fractional volume of pore space and the fractional volume of mobile fluid filling the pore space of earth formations. Methods of using NMR measurements for determining the fractional volume of pore space and the fractional volume of mobile fluids are described, for example, in “Spin Echo Magnetic Resonance Logging: Porosity and Free Fluid Index Determination,” M. N. Miller et al., Society of Petroleum Engineers paper no. 20561, Richardson, Tex., 1990. Further description is provided in U.S. Pat. No. 5,585,720, of Carl M. Edwards, issued Dec. 17, 1996 and having the same assignee as the present application, entitled “Signal Processing Method For Multiexponentially Decaying Signals And Applications To Nuclear Magnetic Resonance Well Logging Tools.” The disclosure of that patent is incorporated herein by reference.
Deriving accurate transverse relaxation time T2 relaxation spectra from nuclear magnetic resonance (NMR) data from logging subterranean formations, or from cores obtained from such formations, is critical to determining total and effective porosities, irreducible water saturations, and permeabilities of the formations. U.S. Pat. No. 6,069,477 to Chen et al. discusses the constituents of a fluid saturated rock and various porosities of interest. The total porosity as measured by a density logging tool is the difference between the total volume and the solid portion. The total porosity includes clay-bound water, capillary bound water, movable water and hydrocarbons. The effective porosity, a quantity of interest to production engineers, is the sum of the last three components and does not include the clay bound water. Accurate spectra are also essential to estimate T2 cutoff values and to obtain coefficients for the film model or Spectral Bulk Volume Irreducible (SBVI) model. Effective porosities are typically summations of partial porosities; however, distortion of partial porosity distributions has been commonly observed for a variety of reasons. These reasons include poor signal-to-noise ratio (SNR), and poor resolution in the time domain of the NMR data.
The most common NMR log acquisition and core measurement method employs T2 measurements using CPMG (Carr, Purcell, Meiboom and Gill) sequence, as taught by Meiboom and Gill in “Modified Spin-Echo Method for Measuring Nuclear Relaxation Time,” Rev. Sci. Instrum. 1958, 29, pp. 688-691. In this method, the echo data in any given echo train are collected at a fixed time interval, the interecho time (TE). Usually, a few hundred to a few thousand echoes are acquired to sample relaxation decay. However, for determination of CBW, echo sequences of as few as ten echoes have been used.
There are numerous examples of wireline NMR logging tools used for obtaining information about earth formations and fluids after a wellbore has been drilled. The logging tools are lowered into the borehole and NMR signals are obtained using different configurations of magnets, transmitter coils and receiver coils. Rig time is expensive, so that the general objective in wireline logging is to obtain interpretable data within as short a time as possible. Depending upon the reservoir, different radio frequency (RF) pulsing schemes for generating RF fields in the formation have been used. The most commonly used pulsing schemes are the CPMG sequence and variations thereof. The parameters that may be varied include the wait time, the number of pulses within a CPMG sequence, and the time interval between the pulses. Long wait times are needed for proper evaluation of the long relaxation times of gas reservoirs while short wait times and/or short pulse spacings are used for evaluating clay bound water (CBW). For example, U.S. Pat. No. 6,331,775, issued to Thern et al, having the same assignee as the present application and the contents of which are fully incorporated herein by reference, discusses the use of a dual wait time acquisition for determination of gas saturation in a formation. U.S. Pat. No. 5,023,551 to Kleinberg et al discusses the use of CPMG sequences in well logging. U.S. Pat. No. 6,069,477 to Chen et al, the contents of which are fully incorporated herein by reference, teaches the use of pulse sequences with different pulse spacings to determine CBW. Phase alternated pairs (PAPs) of sequences are commonly acquired to reduce the effects of ringing.
The commonly used seven conductor wireline is not a serious limitation to two-way communication from the surface to the logging tool. This makes it possible to process data uphole with little or no downhole processing and to send instructions downhole to the logging tool to modify the acquisition schemes based on the surface processing.
In contrast, measurements made with a drilling assembly in the wellbore have several problems. First of all, there is little a priori information available about the actual subsurface formations except that inferred from surface seismic data. As would be known to those versed in the art, the resolution of such seismic data is of the order of several meters to tens of meters. This makes it difficult, if not impossible, to base an acquisition scheme on the basis of expected properties of formations.
Secondly, when the drilling assembly is in a borehole, data communication capability is in most cases severely limited. Telemetry is accomplished either by sending acoustic pulses through the mud or through the drillstring. The data rate with mud pulsing is limited to a few bits per second and communication through the drillstring becomes a serious problem when the drillbit is being operated due to the vibration and noise produced. This makes it impossible to evaluate acquired data at the surface and to modify the acquisition scheme based on this evaluation.
A third problem arises from the nature of NMR data itself. The sensitive volume of commonly used logging tools is no more than a few millimeters in thickness. The RF frequency is tuned to operate at the Larmor frequency corresponding to the static magnetic field in the sensitive volume. Any motion of the tool during drilling can mean that a RF-pulse reaches an area that has not been reached by an earlier excitation or refocusing pulse. This results in a severe degradation of the data. U.S. Pat. No. 5,705,927 issued to Kleinberg discloses making the length of each CPMG sequence small, e.g. 10 ms, so that the drill collar cannot be displaced by a significant fraction of the vertical or radial extent of the sensitive region during a CPMG pulse sequence. However using such short sequences and short wait times only gives an indication of the bound fluid volume and gives no indication of the total fluid volume.
The economic value of an oil and gas bearing formation depends on the amount of producible hydrocarbons contained in the subsurface reservoir. This amount of producible hydrocarbons is a function of the formation porosity and permeability.
NMR measurements for formation evaluation yield signals originating from the precessing protons of the fluids in the pore space of the rock. Due to interactions of the fluid molecules with each other or the pore walls, the signal of each proton decays exponentially with a characteristic time T2 (longitudinal relaxation time).
Permeability is a function of, among other things, the T2 distribution and the pore size distribution. In sandstones, where porosity and permeability is regular, this relationship is fairly consistent and NMR is a reliable method of characterizing reservoirs. Carbonate reservoir porosity and permeability are not so well defined as sandstone and the relationship varies with different lithofacies.
Siliciclastic sediments, such as sandstones and shale, develop through the attrition of other rocks. Their grains are sorted prior to deposition. Sandstones and shale are formed of sedimentary particles derived from sources outside the depositional basin. Siliciclastic sediments are relatively stable after deposition. As a result, the pore space in sandstones is mainly intergranular and its complexity depends on the degree of sorting.
Carbonates form in special environments and, in contrast to sandstones, are biochemical in nature. They are essentially autochthonous, as they form very close to the final depositional sites. They are not transported and sorted in the same way as sandstones. Carbonates are usually deposited very close to their source and develop as a result of various processes. Their texture is more dependent on the nature of the skeletal grains than on external influences. Intrabasinal factors control facies development. Reefs, bioherms, and biostroms are example of in-place local deposition where organisms have built wave-resistant structures above the level of adjacent time-equivalent sediments.
Carbonates are characterized by different types of porosity and have unimodal, bimodal, and other complex pore structure distributions. This distribution results in wide permeability variations for the same total porosity, making it difficult to predict their producibility. In this case, long echo trains with a large number of echoes and a long-pre-polarization time may be applicable. Carbonate rock texture produces spatial variations in permeability and capillary bound water volumes.
Carbonates are particularly sensitive to post-depositional diagenesis, including dissolution, cementation, recrystallization, dolomitization, and replacement by other minerals. Calcite can be readily dolomitized, sometimes increasing porosity. Complete leaching of grains by meteoric pore fluids can lead to textural inversion which may enhance reservoir quality through dissolution or occlude reservoir quality through cementation. Burial compaction fracturing and stylolithification are common diagenitic effects in carbonates, creating high-permeability zones and permeability barriers or baffles, respectively. Diagenesis can cause dramatic changes in carbonate pore size and shape. On a large scale, porosity due to fracturing or dissolution of carbonate rocks can produce “pores” up to the size of caverns.
Given the wide range of origins for carbonate rocks, and the variety of secondary processes which may affect them, it is not surprising that the convoluted pore space of a carbonate may be quite different from that found in siliciclastic sediments. All carbonate sediments are composed of three textural elements: grains, matrix, and cement.
In general, geologists have attempted to classify sedimentary rocks on a natural basis, but some schemes have genetic implications (i.e., knowledge or origin of a particular rock type is assumed).
The relative proportions of the components, among others, can be used to classify carbonate sediments. A widely used classification scheme is proposed by Dunham (see Dunham, “Classification of carbonate rocks according to depositional texture”, in Classification of carbonate rocks—A Symposium, Ham, ed., volume 1, pages 108-121. AAPG Mem., 1962.) In Dunham, carbonates are classified based on the presence or absence of lime mud and grain support. Textures range from grainstone, rudstone, and packstone (grain-supported) to wackestone and mudstone (mud-supported). Where depositional texture is not recognizable, carbonates are classified as boundstone or crystalline. Within these carbonates, the porosity takes many forms, depending on the inherent fabric of the rock, and on the types of processes that can occur during and after deposition.
In many carbonates, it is not possible to map the rock texture using conventional logs. Rock texture exerts a strong influence on permeability variations and bound water distributions—important factors in reservoir simulations. For example, while porosity logs may show little change between grainstones, wackestones and mudstones, the capillary-bound water volumes and permeabilities for these rocks may be very different.
Another classification system, by Lucia (see Lucia, Petrophysical parameters estimated from visual description of carbonate rocks: a field classification of pore space. Journal of Petroleum Technology, 35:626-637, March 1983) is based on petrographical attributes and porosity. Dolomites are included in this classification scheme.
Pore type characterization is used in a classification scheme of Choquette & Pray (see P. W. Choquette and L. C. Pray. Geologic nomenclature and classification of porosity in sedimentary carbonates. AAPG Bull., 54:207-250, 1970). Choquette & Pray, in contrast to Dunham, classify carbonates according to fabric and nonfabric pore types. Examples of the former are inter-and intraparticle porosity, while those of the latter are fractures and vugs. Another classification scheme, by Melim et al., differentiates between primary and secondary pore spaces using the description based on classification of Choquette & Pray. Some of the petrographical information obtained using these classifications are used to improve the petrophysical evaluation of the geological formations.
NMR logging tools use large magnets to strongly polarize hydrogen nuclei in water and hydrocarbons as they diffuse about and are contained in the pore space in rocks. When the magnet is removed, the hydrogen nuclei relax. The relaxation time, T2, depends on the pore-size distribution; larger pores typically have longer relaxation times. Tar and viscous oils relax more quickly than light oil and water. The variations in relaxation time produce a T2 distribution from which fluid components and pore sizes are interpreted. As is well known to those versed in the art, T1 and T2 distributions correlate very well if the diffusion is negligible. In this case, we assume that the cutoff values are equal. The method described herein is applicable for both T1 and T2 distributions.
Two standard permeability equations have been established for applications in the oil industry. The Schlumberger-Doll Research (SDR) equation uses simply the geometric mean of the measure T2 distribution to derive permeability. The Timur-Coates equation uses a T2 cutoff value that divides the T2 distribution into a movable and an irreducible fluid saturation and relates these values to permeability. To improve the permeability prediction, the results of the classification and the data interpretation are used for a variation of the parameters of both equations. U.S. Pat. No. 6,559,639 to Minh et al. describes a method for determination of permeability using the sum of echoes. Other permeability models such as the Kozeny-Carman method may also be used for permeability determination.
Various methods have been proposed to determine formation properties of carbonates using Nuclear Magnetic Resonance. Hidajat et al. (see Hidajat et al., “Study of Vuggy Carbonates using X-Ray CT Scanner and NMR”, SPE 77396, 2002) works to improve correlation between NMR T2 response in carbonate systems, including the contributions of vugs to carbonate permeability. Ramakrishnan et al. (see Ramakrishnan et al., “A Model-based Interpretation Methodology for Evaluating Carbonate Reservoirs”, SPE 71704, 2002) develops an integrated methodology for carbonate interpretation. The methodology of Ramakrishnan parametrizes the pore structure in terms of a multiporosity system of fractures, vugs, inter- and intragranular porosities. NMR data is useful in separating the inter- and intragranular components. The method of Ramakrishnan requires the use of more services than are normally run to provide data.
There is a need for an apparatus and method of obtaining NMR measurements while a wellbore is being drilled through a carbonate formation that is able to modify the acquisition and processing parameters with a minimum of communication with the surface. Such an invention should preferably be able to adjust the acquisition depending upon actual downhole conditions. The method should preferably be robust in the presence of vibration of the logging tool. There is also a need for evaluating carbonates using a method restricted to NMR and carbonate classification only. The present method satisfies this need.